Gas Separator Assembly For Generating Artificial Sump Inside Well Casing

ABSTRACT

A gas separator assembly generates an artificial sump in a production casing receiving a production tubing string with a downhole pump at the bottom end thereof. The assembly includes an inner casing in series with the production casing of the well and an outer casing supported externally of the inner casing. First and second ports at opposing top and bottom ends of the outer casing communicate from a primary passage in the inner casing to a secondary passage between the inner and outer casings. A barrier supported in the primary passage between the first and second ports diverts flow through the secondary passage and effectively defines the sump area in the primary passage between an inlet of the downhole pump adjacent the barrier and the first port thereabove.

CROSS REFERENCE TO RELATED APPLICATION

This application is a continuation of U.S. application Ser. No.15/347,189, filed Nov. 9, 2016, now U.S. Pat. No. 9,909,400, which is acontinuation of U.S. application Ser. No. 14/059,303, filed Oct. 21,2013, now U.S. Pat. No. 9,518,458, which claims the benefit of U.S.Provisional Application Ser. No. 61/795,597, filed Oct. 22, 2012.

FIELD

The present invention relates to a gas separator assembly and a methodof preparing a well containing gas and liquid for pumping by connectingthe gas separator assembly in series with the outer casing of the wellwhen completing the well, and more particularly the present inventionrelates to a gas separator assembly defining a primary passage in serieswith the well casing for receiving a barrier therein and a secondarypassage which diverts produced fluids past the barrier externally of theprimary passage in series with the casing to define an artificial sumparea immediately above the barrier which receives the pump therein.

BACKGROUND

When pumping from a hydrocarbon producing well containing gas and liquidit is known to be desirable to separate the gas from the liquid in orderfor the pump to operate effectively. Known gas separators have variousdeficiencies such that gas interference, resultant gas-locking, andpotential resultant damages to downhole pumping equipment, as well asdowntime and deferred production is an ongoing problem.

Most horizontal wells are completed with 5.5 inch and sometimes 4.5 inchproduction casing strings in all current domestic gas and oil plays.This leaves roughly 4.00 to 4.75 inches to convey and operate any formof artificial lift (AL) and gas separator. There are numerous gasseparation techniques used for each form of AL, but most are moderatelysuccessful at best and some do a very poor job, but may be the onlyoption.

For reciprocating rod pump the most common form of separation is themodified poor boy gas separator. A representative diagram is attached asFIG. 1.

For electrical submersible pumps (ESP's) the most common form of gasseparation in horizontal wells is the rotary gas separator. This allowsthe pump to expel a reasonable volume of gas to the annulus after beingingested at the intake of the pump by way of centrifugal farce. Oneexample is disclosed in U.S. Pat. No. 4,981,175 by Conoco Inc.

For progressive cavity pumps (PCP's) the most common form of gasseparation is to run either an orienting intake sub which orients theintake: ports of the tailpipe to the lowermost portion of the wellboreaiming to avoid gas intake. Also, there is a diversion type separatorwhich redirects the flow of gas and fluids up and around the pump thendumps the fluids annularly down to the intake while the gas travelsupward to the surface. One example is disclosed in U.S. Pat. No.7,270,178 by Baker Hughes Incorporated.

The 3 AL forms listed above are 3 of the 5 most popular and widely usedforms of AL in all oil and gas wells completed today. The other two aregas lift and jet pump.

The most effective form of separation in horizontal wells has come byway of a sump or an extended section off the primary production casingthat is drilled post completion, often at a tangent in the curves buildsection typically at 30 to 60 degrees, allowing for fluids to fall to apump set below and allowing gas to break and travel upward. This is acostly method of separation due to added drilling and completion costsand there are risks involved such as wellbore stability and integrityissues, possibility to have issues running tools into the lateral, etc.

Additional examples of gas separators are described in U.S. Pat. No.6,932,160 by Murray et al, U.S. Pat. No. 7,055,595 by Mack et al, U.S.Pat. No. 4,676,308 by Chow et al, and U.S. Pat. No. 2,883,940 by Gibsonet al. Known gas separator devices can typically have limitedeffectiveness while occupying large amounts of space within the interiordiameter of the well casing such that insertion and removal from thewell casing may be awkward and difficult, and/or limited access isprovided for other downhole tools if desired.

SUMMARY

The present invention proposes generating an artificial sump inside theexisting production casing. The benefit is that in most cases noincremental drilling/completion costs will be incurred and nooperational issues should be incurred as the ID of this tool will beequal to or greater than the remainder of the production casing.

According to one aspect of the invention there is provided a gasseparator assembly for a use with a downhole pump supported at a bottomend of a production tubing string received within an outer casing of ahydrocarbon producing well, the assembly comprises an inner casingmember defining a primary passage extending longitudinally therethroughbetween opposing first and second ends of the assembly so as to bearranged for connection in series with the outer casing of the well, anouter casing member supported externally of the inner casing member soas to define a secondary passage extending longitudinally and externallyof the primary passage between a first end and a second end of thesecondary passage, at least one first port in communication between theprimary passage of the inner casing member and the secondary passage ofthe outer casing member adjacent the first end of the secondary passagesuch that the first end of the secondary passage only communicates withthe primary passage through said at least one first port, at least onesecond port in communication between the primary passage of the innercasing member and the secondary passage of the outer casing memberadjacent the second end of the secondary passage such that the secondend of the secondary passage only communicates with the primary passagethrough said at least one second port and a barrier arranged to besupported in the primary passage to seal the primary passage at alocation between said at least one first port and said at least onesecond port so as to define a sump area in the primary passage betweenthe barrier and said at least one first port which is arranged toreceive an inlet of the downhole pump therein whereby produced fluids inthe outer casing below the assembly are directed from the outer casingbelow the assembly upwardly through the secondary passage from said atleast one second port to said at least one first port and downwardlythrough the primary passage from said at least one first port to theinlet of the downhole pump.

Preferably the inner casing member extends substantially concentricallythrough the outer casing member such that the secondary passage isgenerally annular about the primary passage.

In other embodiments, the outer casing member may comprise one or moreauxiliary tube members extending alongside the inner casing member todefine the secondary passage as a plurality of longitudinally extendingpassages at circumferentially spaced locations about the primarypassage.

Preferably an interior diameter of the primary passage is substantiallyequal to an interior diameter of the outer casing.

According to a second aspect of the present invention there is provideda method of preparing a hydrocarbon producing well containing gas andliquid for pumping using a downhole pump supported at a bottom end of aproduction tubing string, the method including providing a gas separatorassembly comprising an inner casing member defining a primary passageextending longitudinally therethrough between opposing first and secondends of the assembly an outer casing member supported externally of theinner casing member so as to define a secondary passage extendinglongitudinally and externally of the primary passage between a first endand a second end of the secondary passage at least one first port incommunication between the primary passage of the inner casing member andthe secondary passage of the outer casing member adjacent the first endof the secondary passage such that the first end of the secondarypassage only communicates with the primary passage through said at leastone first port and at least one second port in communication between theprimary passage of the inner casing member and the secondary passage ofthe outer casing member adjacent the second end of the secondary passagesuch that the second end of the secondary passage only communicates withthe primary passage through said at least one second port and connectingthe first and second ends of the assembly in series with the outercasing such that the primary passage communicates in series with aprimary passage of the outer casing while completing an outer casing ofthe hydrocarbon producing well.

One embodiment of the invention will now be described in conjunctionwith the accompanying drawings in which:

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of a prior art gas separator knownas a modified poor boy gas anchor; and

FIG. 2 is a sectional side elevational view of the gas separatorassembly according to the present invention.

In the drawings like characters of reference indicate correspondingparts in the different figures.

DETAILED DESCRIPTION

Referring to the accompanying figures there is illustrated a gasseparator assembly generally indicated by reference numeral 10. Theassembly 10 is particularly suited for use with a downhole pumpsupported on the bottom end of a production tubing string and arrangedto be received within the outer casing 12 of a well containing liquidand gas. The assembly 10 is mounted in series with the outer casing 12of the well as the well is completed. Subsequent to completing the wellwith the assembly 10 mounted therein, the production tubing string iiwith the downhole pump 13 at the bottom end thereof are conveyed intothe outer casing 12 and the assembly in series therewith in the usualmanner of conveying production tubing into a well.

The assembly 10 generally includes an inner casing member 20, an outercasing member 22 concentrically receiving the inner casing extendinglongitudinally therethrough, and a barrier member 24 arranged to bereceived within the inner casing member to selectively seal the passagethrough the inner casing member as described in further detail below.

The inner casing member 20 is an elongate cylindrical tubular memberwhich defines a primary passage extending longitudinally along the fulllength thereof between a top first end 26 and a bottom second end 28 ofthe assembly. The longitudinally opposed ends of the inner casing memberat the first and second ends of the overall assembly respectively aresuitably configured for connection in series with correspondingconnections within the outer casing. The inner casing member is suitablysized such that the interior diameter of the primary passage extendingtherethrough is approximately equal to an interior diameter of the outercasing of the well.

The outer casing member 22 is similarly elongate in the longitudinaldirection in the form of a cylindrical tubular member which is generallyin the form of a sleeve which surrounds the inner casing membersubstantially along the full length thereof. The outer casing member islarger in diameter than the inner casing member so as to define asecondary passage in the annular space between the inner diameter of theouter casing member and the outer diameter of the inner casing memberwhich spans the full length of the outer casing member in thelongitudinal direction between a top first end 30 and a bottom secondend 32. The first and second end each include annular end walls 34 forenclosing the respective opposing ends of the secondary passage toprevent communication of the secondary passage with the area outside ofthe remainder of the outer casing of the well.

A plurality of first ports 36 communicate through the wall of the innercasing member for communication between the primary passage and thesecondary passage extending externally alongside the primary passage ata location in close proximity to the first end 30 of the casing members.The first ports are located at the same longitudinal position at evenlyspaced apart positions in the circumferential direction. The annular endwall at the first end ensures that the first end of the secondarypassage only communicates with the primary passage through the firstports 36.

Second ports 38 are similarly located in close proximity to the secondends of the casing members for communication between the primary passageand the secondary passage. The second ports 38 are similarly located ata common longitudinal position at evenly spaced apart locations in thecircumferential direction. The annular end wall at the second end of thesecondary passage ensures that the second end of the secondary passageonly communicates with the primary passage through the second ports.

In this instance, flow of fluid up through the outer casing from aproduction zone below the assembly 10 enters through the primary passageat the bottom of the assembly and can flow up through the primary orsecondary passages when the passages are open such that there issubstantially no pressure deferential across the wall of the innercasing defining the boundary between the primary and secondary passages.As the balancing of pressure from the primary passage to the secondarypassage through the ports limits any pressure deferential across thewall of the inner casing, the wall thickness of the inner casing membercan be thinner than the outer casing member which has a thicker wall forcontaining the overall pressure within the outer casing.

A sleeve member 40 may be optionally located within the inner casing inproximity to either the first ports or the second ports. Typically, thesleeve member is mounted in proximity to the first ports so as to bemore accessible. The sleeve member 40 is mounted so as to be moveablefor sliding movement in the longitudinal direction of the casing betweenopen and closed positions relative to the respective ports. When mountedfor operation relative to the first ports, the communication between theprimary and secondary passages through the first ports is unrestrictedin the open position. In the closed position, the sleeve member isaligned with the first ports to span across the ports and maintain theports closed, thereby preventing flow between the primary and secondarypassages through the first ports. Even in the closed position of thesleeve member however, the pressure between the primary and secondarypassages remains balanced by the open communication through the secondports.

The barrier member 24 is arranged to be supported in the primary passagein the form of a plug member which seals the passage closed once set.The barrier can be similar to many conventional forms of plugs forforming a seal across the passage of the outer casing and is typicallyset in place by various forms of downhole equipment. The barrier is setat a location directly above the second ports towards the bottom end ofthe assembly to define an artificial sump area within the primarypassage of the inner casing member which spans longitudinally from thebarrier to the first ports spaced well above the barrier adjacent theopposing top end of the assembly. The cross sectional area of theartificial sump area corresponds to the full interior diameter of theprimary passage which in turn corresponds approximately to the fullinterior diameter of the outer casing of the well.

Once the barrier is installed and the sleeve member is located in theopen position, the downhole pump can be located within the artificialsump area with the inlet of the pump preferably being located at thebottom of the pump spaced directly above the barrier at a locationspaced well below the first ports. The pump may take various formsincluding an electrical submersible pump, a progressive cavity pump, areciprocating rod pump, a hydraulic reciprocating pump, or a jet pumpfor example. In either instance, the pump is located fully above thebarrier so as to be supported within the well casing independently ofthe barrier.

The barrier remains readily releasable and separable from the innercasing member using suitable downhole equipment to perform otherwellbore operations as may be desired. When performing other wellboreoperations, the sleeve member 40 is typically closed so that fluids aredirected through the primary passage rather than the secondary passage.

In use, the inner and outer casing members are installed when completingthe outer casing of the well. When the barrier is not installed (and thesleeve member is closed across the first ports if provided), the passagethrough the assembly spans substantially the full interior diameter ofthe inner casing member which in turn corresponds to the interiordiameter of the outer casing member of the well so that the assembly hasno interference with any other normal well operations within the casing.

When it is desired to produce hydrocarbons from the well which containgas and liquid by pumping, the barrier is first placed within theprimary passage between the first and second ports at a location inclose proximity to the second ports and the sleeve member is opened. Bylocating the downhole pump directly above the barrier and spaced wellbelow the first ports, operation of the pump causes gas and liquidflowing up from the casing below the assembly to be directed by thebarrier externally of the main passage of the inner casing through thesecondary passage. The flow of liquid and gas together continue to flowup the secondary passage from the second ports to the first ports wherethe gas and liquid then returns to the primary passage. At the firstports, the denser fluid tends to be drawn downwardly into the artificialsump area above the barrier where the inlet of the pump is located.Meanwhile, separated gas is directed primarily upwardly from the firstports through the primary passage and subsequently through the annulusof the well surrounding the production tubing string within the outercasing.

The large diameter of the artificial sump area occupying substantiallythe full diameter of the outer casing of the well and spanning a largeheight from the first ports to the barrier provides a considerableresidence time for fluids to allow more gas to separate naturally withinthe artificial sump area before the fluid reaches the inlet of the pumpat the bottom of the sump area directly above the barrier. Accordingly,substantially only liquid is drawn upwardly into the inlet at the bottomend of the downhole pump to be subsequently pumped up through theproduction tubing string.

According to one preferred embodiment of the present invention describedabove, the gas separator assembly will consist of a single joint ofcasing, matching the planned OD production casing. For example: 5.5″casing will accept a 5.5″ casing gas separator interior string. Thisinterior string will have either a sliding sleeve or 4 to 6 holesdrilled to 1.25″ diameter in a 90 or 60 degree phasing pattern. Theholes or inlets of the sleeve will be spaced approximately 1.0′ from thepin ends of the interior string. The casing weight of the interiorstring will be minimized as this section will not support anydifferential pressure while under operation and the reduced density willhelp the joint to be located with casing collar locator tools.

The connections will match that of the other planned production casing,typically LT&C.

The exterior shroud will consist of a single joint of larger OD casingsuch as 7″ 32# to shroud the length of 5.5″ interior siring. There is a0.044″ clearance between the 5.5″ couplings and the ID of the 7″ whichwill be welded, inspected, and pressure tested for integrity. Weldingthe outer shroud will generate a sealed outer annulus between the 5.5″and the 7″.

The unit will run in on the production casing and be set at apredetermined inclination, likely at kick off point. Alternativeset-points could be accommodated and would be advisable if a tangentsection was drilled for the unit to be placed in. It is also aprobability that more than one unit may want to be run with one at kickoff and the other lower in a tangent of 60 degrees for example. Thiswould allow for multiple setting depth options for pumping equipmentover the life of the well as changing conditions would dictate.

The function of the unit would be to divert all produced gas, oil, andwater into the bottom ports, through the clearance of the outer sheathand inner string, allowing fluids to dump out the top ports and down toa pump set below the top ports and above the bottom ports.

In some instances the barrier may be installed by first running awireline set packer with a pump-out plug immediately above the bottomports, although any other type of barrier or plug can be used. Settingimmediately above the bottom ports will yield the most footage from thetop ports and create the most effective and largest artificial sumppossible. It is estimated that a 30 foot sump would result afterinstallation of the packer.

The effectiveness of this type of separation is unparalleled for manyreasons. The simple physics of this style diversion have proven to bevery effective when put to use in systems contained within the nominalcasing ID. The lighter gas travels up and the fluids fall down, plainand simple. Also, when referencing entrained gas in fluids, notablyheavy oil, residence time in a separator to allow further breakout ofgas is a key element. Residence time is simply the amount of time ittakes to drop fluids from the upper discharge ports to the pump intake.Having the largest diameter possible via the casing ID to contain thefluids as they proceed to the intake will yield superior residence timeswhen compared to existing gas separator systems which are fullycontained within the casing and are of much smaller cross-sectional areaand are typically shorter.

By retaining at least the same or larger ID as the rest of theproduction casing, it will be possible to pass all tools and equipmentrelated to completions such as bits, scrapers, fishing tools, tubing,coiled tubing, TCP guns, pump down plugs, bridge plugs, etc. that wouldbe required to pass the ID of the normal production string. Further, byshrouding with a much heavier weight external shroud the desiredtreating pressures for the rest of the production casing would bemaintained. To protect against solids and cement build-up and blockage,it may be necessary to run a sliding sleeve in the place of the open topports to keep the casing separator's annulus clear and unobstructed.This would also help when pumping down frac plugs and other tools whenthe unit is set at inclination in excess of 45 degrees due to theprobability of tools stalling when excess friction is seen and a lack ofdifferential is able to be achieved if the pump down fluids are divertedto the annulus when said tools pass the open top ports and are pumpeddown.

The casing annulus separator described herein is typically run in when anew well is first completed.

Since various modifications can be made in my invention as herein abovedescribed, and many apparently widely different embodiments of same madewithin the spirit and scope of the claims without department from suchspirit and scope, it is intended that all matter contained in theaccompanying specification shall be interpreted as illustrative only andnot in a limiting sense.

1-20. (canceled)
 21. An assembly, comprising: a first well casing; apipe disposed within the first well casing; a pump in fluidcommunication with the pipe, the pipe having a distal inlet; acontainment structure disposed about the distal inlet; and a first portdisposed on the containment structure; wherein the assembly defines afluid flow path, wherein a combined fluid stream is separated into aheavy fluid stream and a light fluid stream at the first port, the heavyfluid stream extending through the first port into the containmentstructure and into the distal inlet, the light fluid stream extendinggenerally upwardly in an annular space within the well casing around thepipe.
 22. The assembly of claim 21 wherein the containment structuredefines a sump area between the first port and the distal inlet of thepipe.
 23. The assembly of claim 21 in which the containment structurecomprises a barrier to prevent the combined fluid stream from enteringthe containment structure from other than the first port.
 24. Theassembly of claim 23 in which the containment member is configured forconnection to a well casing.
 25. The assembly of claim 21 furthercomprising a second port formed in the containment member below thedistal inlet.
 26. The assembly of claim 25 in which a barrier is formedbetween the second port and the pump inlet.
 27. The assembly of claim 26in which the fluid flow path extends from the containment member, outthe second port into an annular space around the containment member, tothe first port.
 28. The assembly of claim 21 in which the fluid flowpath extends from an annular space around the containment member to thefirst port.
 29. The assembly of claim 21 in which the heavy fluid streamis substantially only liquid.
 30. The assembly of claim 21 in which gaswithin the combined fluid stream primarily enters the light fluid streamwhen the fluid flow path passes the first port.
 31. The assembly ofclaim 21 wherein the containment structure is situated within anexpanded well casing section having a greater diameter than the firstwell casing.
 32. The assembly of claim 31 wherein the diameter of thefirst well casing is approximately 5.5 inches and wherein the diameterof the expanded well casing section is 7 inches.
 33. The assembly ofclaim 21 wherein the inner diameter of the containment structure issubstantially identical to the inner diameter of the first well casing.34. The assembly of claim 21 in which a plurality of first ports arespaced about the containment structure.
 35. The assembly of claim 21further comprising a sleeve moveable between a position to close thefirst port and a position to open the first port.
 36. The assembly ofclaim 21 in which the pump is an electrical submersible pump or areciprocating rod pump.
 37. The assembly of claim 21 in which the pumpis disposed within the pipe.
 38. A method of separating gas from acombined fluid stream being produced in a well, the method comprising:providing a barrier to direct combined fluid into an annular spaceformed about a containment structure; providing a production tubingstring in fluid communication with a pump, the pump displacing fluid ata pump inlet disposed within the containment structure; and separatingthe combined fluid into a gas-rich stream and a gas-poor stream at afirst port of the containment structure such that the gas poor streamextends through the containment structure to the pump inlet and thegas-rich stream extends within an annular space around the productiontubing string.
 39. The method of claim 38 in which the combined fluidstream flows through an expanded casing region, the expanded casingregion having an outer diameter greater than the outer diameter of aprimary casing region.
 40. The method of claim 38 comprising creating anartificial sump within the containment structure between the first portand the pump inlet.